January 20, 2017 • Vol. 7, No. 1docFinder alert
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Marcellus producers turn soft prices into increased volumes


Cabot all-in Marcellus-only F&D costs are $0.31/Mcfe


June 27, 2016

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Range earns 54% ROR on SW Penn. dry gas assets

Range Resources

December 1, 2016

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The plunge in oil, liquids, and natural gas prices over the last two years led to dramatic plunges in industry investment that has stunted output growth in US unconventional resource plays—with one exception. For most of that period, the Marcellus Shale output defied gravity, increasing 41% from a little over 11 Bcf/d in January 2014 to over 16.7 Bcf/d in November 2016, compared with a 9% drop from total production in six other major natural gas plays (Antrim, Woodford, Barnett, Eagle Ford, Fayetteville, Haynesville). This Marcellus output surged despite a 60% reduction in investment by gas-weighted US producers and a 76% drop in rig count from 86 to just 21 in early 2016. This growth is even more remarkable when regional gas realizations are considered. Severe restrictions on regional takeaway capacity and leveling of demand resulted in prices that plunged to as low as $0.65/MMBtu in early 2015 and an average $1.65/MMBtu below Henry from January through June.

Recently, ten-year strip prices have climbed above $3.00/MMBtu and gradually increasing takeaway capacity has narrowed differentials for Marcellus producers to well under $1.00/MMBtu. The industry responded to the brightening prospects by nearly doubling the Marcellus rig count to 46 at the end of December 2016, and a group of eight major Marcellus producers have announced an average 46% increase in 2017 capex. We wondered how these E&Ps managed to survive the rock bottom prices while maintaining sufficient financial strength to boost investment in 2017 and beyond, so we turned to docFinder to access presentations for a quick snapshot of the current economics of the major Marcellus players.

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Cabot Oil and Gas’ most recent results highlight a major reason—a rock bottom cost structure. Cabot stated its 2015 Marcellus-only finding and development costs were $0.31/Mcfe and its Q1/16 Marcellus only cash operating expenditures were $0.79/Mcfe. All-in expenses of $1.10/Mcfe allowed the company to weather the worst parts of 2015 and generate $104 million in cash flow in Q3/16, when its average realization climbed to $1.75/MMBtu. With rising strip prices, the company is betting that it will internally fund an increase in its exploration and development spending program for 2017 from $325 million to $575 million, which it expects to translate into a 5-10% company-wide production gain.

Range Resources also boasts strong profitability at low natural gas prices for its southwestern Pennsylvania dry gas Marcellus wells, where it owns 180,000 net acres. The company says that these dry gas wells earn a 54% rate of return at a $3.00/MMBtu Henry Hub price, net of basis differentials and gathering and transportation costs. Range’s F&D costs are similar to Cabot Oil & Gas at $0.36/Mcf which is based on a $5.20 million drilling and completion cost per well and an estimated ultimate recovery of 17.6/Bcf. In 2017, Range expects organic production growth of 11%-13% (primarily Marcellus). The firm recently spent $4.4 billion acquiring Memorial Resource Development assets in North Louisiana, where proximity to Gulf Coast markets results in dramatically lower differentials. But overall, Range estimates total returns from the Marcellus will match its new properties because of lower drilling and operating costs in tandem with improving takeaways.

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featured.slides from docFinder

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Marcellus drives EQT's production growth

December 14, 2016

Rice Energy

New takeaway capacity improves realizations

November 29, 2016


Rich gas assets provide strong returns

December 7, 2016


Wet Marcellus assets lackluster for Range

December 1, 2016

EQT Corp has 720,000 net acres in the Marcellus, including 3,300 core drilling locations with strong economics. For its 7,000 foot laterals, EQT earns an after-tax internal rate of return (IRR) of 15% at $2.00/MMBtu, increasing to 43% at $2.50/MMBtu and 89% at $3.00/MMBtu. EQT states that it now costs $5.70 million to drill a well (7,000 foot lateral) that can recover 14.7 Bcfe economic ultimate recovery. The company also says the economics of the wells improve with longer laterals. A 9,000 foot lateral earns a 19% IRR at $2.00/MMBtu and a 115% at $3.00/MMBtu. These strong economics are based on cheap F&D costs, similar to Range and Cabot. Based on these positive economic results, EQT is expected to increase production ~9.0% in 2017 and an additional 18-20% in 2018. This is a result of a 50% increase in 2017 capital spending to $1.5 billion after the company slashed investment by 40% between 2014-2016.

Obviously, economics for gas producing assets in Appalachia will improve with new pipeline projects coming online. Rice said that 47 rigs were running in Appalachia (Marcellus (32) and Utica (15)) at the end of Q3/16, and that about 45-50 rigs are required just to keep current production flat at 22 Bcf/d (16.7 Bcf/d Marcellus, 4.6 Bcf/d Utica). With an ~18 Bcf/d of incremental firm transportation capacity coming on line by 2019, up to 125 rigs would be needed to provide enough production to keep those pipelines filled. This additional capacity will slash the basis differential at Tetco M2 in half from -$1.20/MMbtu in 2016 to -$0.66/MMBtu, further increasing the returns on Appalachian gas assets.

Antero Resources has exposure to the rich (wet) gas play in the Marcellus. The company shows that even within the rich gas play, well economics can vary significantly. In the accompanying chart, Antero shows the economics of its highly rich gas/condensate and highly rich gas plays. Using the 12/1/16 oil and gas strip prices and a mid-point of economic ultimate recoveries for each well and a $7.80 million well cost, the highly rich gas/condensate play generates a 90% pre-tax rate of return, while the highly rich gas play earns a 58% pre-tax rate of return. Both plays boast low F&D costs, $0.38/Mcfe and $0.42/Mcfe, respectively. However, the NYMEX breakeven gas price is substantially different, $0.89/MMBtu for the highly rich gas/condensate play and nearly twice that level for the highly rich gas play. In 2017, Antero is expecting a 23% increase in total production to 2.2 Bcfe/d, including a more than 50% of increase in liquids output. Antero expects to accomplish this while keeping exploration and development capital spending flat at $1.3 billion in 2017.

Range Resources also has wet Marcellus gas wells but the economics do not appear to be as rosy as its dry gas assets or Antero’s wet gas wells. At a $3.00/MMBtu gas price and oil prices of $50/bbl in 2017 and $65/bbl thereafter, Range Resources’ wet gas wells are expected to earn a 25% rate of return. In contrast, Range’s dry gas wells earn a 54% return and Antero’s rich gas wells earn a 58% return under slightly less aggressive price scenarios. Range’s wet gas wells have a EUR of 20.6 Bcfe composed of 50% natural gas and 50% liquids with the vast majority of those liquids being NGLs. At a well cost of $5.80 million, F&D costs are a very competitive $0.34/Mcfe. Range says it is the only producer with current capacity on Mariner East, the Sunoco Logistics-owned NGL pipeline taking natural gas liquids from Appalachia for delivery to domestic markets and to the Marcus Hook NGL hub to access international markets. The pipeline gives Range the option to sell propane into Europe, which could boost returns from its wet gas assets.


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